Offshore gas fields in many parts of the world produce natural gas containing a significant amount of carbon dioxide (e.g. greater than 10 vol % CO2). For example, the CO2 content of natural gas streams originating offshore can be as high as 80 vol %.
In contrast, at onshore locations where natural gas is to be used, the natural gas should generally have a relatively low CO2 content. For example, a lower CO2 content corresponds to a higher heating value for the natural gas. CO2 can also lead to freezing in the low-temperature chillers in liquified natural gas (LNG) plants.
There are two main approaches to upgrading natural gas offshore. The first approach involves blending the gas with sufficiently low CO2 gas to reduce the overall CO2 content. The second, alternative approach involves subjecting the gas to some type of CO2 removal process.
Various CO2 removal processes are known in the art. They include absorption processes such as those using an amine solvent solution (e.g. methyl-diethanol amine and water), cryogenic processes, adsorption processes such as pressure swing adsorption (PSA) and thermal swing adsorption (TSA), and membrane-based processes.
Membranes have been utilized for two main CO2 removal applications. The first CO2 removal application is sweetening natural gas. The second CO2 removal application is enhanced oil recovery (EOR). In EOR, natural gas removed from a functioning oil well is subjected to CO2 removal and the CO2 is reinjected into the oil well to enhance oil recovery.
Currently, commercially used membranes for CO2 removal from natural gas are polymer membranes. These polymer membranes include cellulose acetate, polyimides (e.g. Matrimid® available from Huntsman Advanced Materials, Basel, Switzerland), polyamides, polysulfone, polycarbonates, polyetherimide, and perfluoropolymer membranes. Cellulose acetate membranes are the most widely used.
However, these commercially used polymer membranes exhibit limited CO2 permeance and limited CO2/CH4 selectivity. Due to the limited CO2 permeance, a large number of membrane modules are required when treating large natural gas flow rates with these membranes. Moreover, due to the limited CO2/CH4 selectivity, a significant amount of methane ends up in the CO2-rich permeate stream when treating natural gas with these membranes. Such slipped methane is particularly unwanted because methane provides significant heating value to natural gas.
The problem of slipped methane has been managed with the methods of venting, flaring, reinjection, and sequestration. However, these coping methods have serious disadvantages when CO2 must be removed from natural gas containing a significant amount of carbon dioxide.
Venting involves releasing the CO2-rich permeate stream to the atmosphere. If currently available polymer membranes, having limited permeance and selectivity, are used to upgrade a 20-35 vol % CO2 natural gas stream to a 8-23 vol % CO2 natural gas stream, they provide a permeate stream having between about 80 vol % and about 90 vol % CO2 and between about 10 vol % and about 20 vol % methane. Venting such a permeate stream is objectionable from an environmental standpoint, especially under active or emerging greenhouse gas (GHG) regulations. Venting such a large amount of methane is particularly objectionable because the GHG value of methane is about 21 times the GHG value of CO2 on a mass basis.
Flaring involves burning off unwanted, flammable gas. Thus, flaring the CO2-rich permeate stream will burn the methane and only release CO2. However, the CO2-rich permeate stream, originating from conventional polymer membranes and containing approximately 80-90 vol % CO2, is typically too lean to flare. Thus, either a portion of the natural gas stream fed to the membrane or the CO2-depleted product gas stream must be blended, as a flare-assist gas, with the CO2-rich permeate. While flaring avoids venting methane as a GHG to the atmosphere, flaring is economically objectionable because a portion of the natural gas fed to the membrane or the CO2-depleted product gas must be diverted from sales for blending. Also, flaring still emits CO2 present in the CO2-rich permeate and CO2 formed from combustion of methane present in the CO2-rich permeate and the flare-assist gas.
Reinjection involves compressing and reinjecting the CO2-rich permeate into an area from which the CO2 in the CO2-rich permeate originated and/or a different area from which the CO2 originated, for example, a different underground formation or strata. For example, reinjection may involve compressing and reinjecting the CO2-rich permeate into a functioning oil well, cyclically, as done during EOR Sequestration involves compressing and reinjecting the CO2-rich permeate permanently into any area, including areas others than the area from which the CO2 in the CO2-rich permeate originated. For example, CO2 may be compressed and sequestered permanently, in a saline aquifer, a depleted oil reservoir, or some other geologic formation, terrestrial formation, or body of water. Problems associated with sequestration and reinjection are related to requisite pressure increase. Both sequestration and reinjection require compression of CO2 and methane to high pressures, which in turn requires significant power. While the CO2-rich permeate can be reinjected as a supercritical fluid that is easily pumpable, due to the 10-20 vol % CH4 present in the CO2-rich permeate, significant pressurization and correspondingly significant power is still required to compress the CO2-rich permeate to a supercritical state.
Therefore, there is a need for a process for producing a CO2-depleted product gas stream from natural gas containing a significant amount of carbon dioxide (e.g. greater than 10 vol % CO2). Such process should require minimal equipment weight and energy and take up minimal space. Moreover, such process should exhibit minimal hydrocarbon losses to the CO2-rich permeate. Accordingly, such process will be useful for upgrading natural gas offshore, will be profitable, and will result in minimal GHG emissions.